Several controlled pressure drilling techniques are used to drill wellbores with a closed-loop drilling system. In general, controlled pressure drilling includes managed pressure drilling (MPD), underbalanced drilling (UBD), and air drilling (AD) operations.
In the Managed Pressure Drilling (MPD) technique, the drilling system uses a closed and pressurizable mud-return system, a rotating control device (RCD), and a choke manifold to control the wellbore pressure during drilling. The various MPD techniques used in the industry allow operators to drill successfully in conditions where conventional technology simply will not work by allowing operators to manage the pressure in a controlled fashion during drilling.
During drilling, for example, the bit drills through a formation, and pores become exposed and opened. As a result, formation fluids (i.e., gas) can mix with the drilling mud. The drilling system then pumps this gas, drilling mud, and the formation cuttings back to the surface. As the gas rises up the borehole in an open system, the gas expands and hydrostatic pressure decreases, meaning more gas from the formation may be able to enter the wellbore. If the hydrostatic pressure is less than the formation pressure, then even more gas can enter the wellbore.
A core function of managed pressure drilling attempts to control kicks or influxes of fluids as described above. This can be achieved using an automated choke response in a closed and pressurized circulating system made possible by the rotating control device. A control system controls the chokes with an automated response by monitoring flow in and out of the well, and software algorithms in the control system seek to maintain a mass flow balance. If a deviation from mass balance is identified, the control system initiates an automated choke response that changes the well's annular pressure profile and thereby changes the wellbore's equivalent mud weight. This automated capability of the control system allows the system to perform dynamic well control or CBHP techniques.
The chokes of the manifold have a non-linear response. This can make it difficult to determine the true position of the chokes and properly control pressure and flow as conditions change. Additionally, hydraulic power is typically supplied remotely to the chokes by a hydraulic power unit (HPU). Typically, the power unit has a hydraulic pump, an accumulator, and a directional control valve (which can be solenoid-activated). During managed pressure drilling, the solenoid valve is driven by a feedback control loop that uses position measurements of the choke's piston. In the early morning hours of operation, the temperature inside the accumulator and unit's hydraulic reservoir reaches the lowest point of the day. With this low temperature, the nitrogen gas energy in the accumulator is low, and the viscosity of the hydraulic fluid us high. The lower internal Nitrogen pressure of the accumulator allows more hydraulic fluid to enter the accumulator while reaching the set hydraulic system pressure.
Having a greater percentage of hydraulic fluid and less energized gas in the accumulator reduces the velocity of hydraulic fluid leaving the accumulator. Consequently, the morning fluid flowrate that drives the choke is slower, and the response of the choke appears more sluggish than it would at hotter times of the day, when accumulator pressure rises and viscosity drops. The daily temperature cycle causes the MPD system to behave differently depending on the time of day. Another factor that changes hydraulic fluid temperature is the average work load over time. For example, when the MPD system is opening/closing the chokes more frequently, the hydraulic fluid temperature will rise.
Unfortunately, operators are typically trained to use the equipment at a certain operating temperature. Therefore, the operators may tend to find that there is a different and unexpected behavior at another temperature. In particular, the set control variables suited for lower temperatures will cause the choke response to be faster in the afternoon due to the increased Nitrogen energy in the accumulator bottle and the lower viscosity of the hydraulic fluid. This increases the chances of overshooting the target choke position. In fact, choke opening and closing times may vary by around 30% throughout the day, or even depending on whether the equipment is in shade or direct sunlight. Likewise, the set control variables suited for higher temperatures will cause the choke response to be slower to reach set point values as operations continues into the night and morning hours, as a cold front suddenly drops temperatures, etc.
There is a needle valve located in the hydraulic power unit that is used to throttle the flow leading up to the chokes. The needle valve is meant to be set to a position that will allow an optimal flowrate to drive the chokes. Usually, the needle valve is set at the beginning of a job or during a factory acceptance test.
It is recognized that electric actuation of the chokes may have faster response times (i.e., closing and opening times for the chokes) when compared to hydraulic actuation. However, electric actuation on the drilling rig may not be desirable or even possible for various reasons so that hydraulic actuation may be preferred. Therefore, what is needed is a way to mitigate any timing differences that may occur in the choke response in a choke manifold for a drilling system as temperatures change. Therefore, the subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.